1. Field of the Invention
The invention relates to drilling fluids for forming oil, gas and water wells.
2. Description of the Prior Art
Drilling fluid or "mud" is a mixture of (refined) clays, usually bentonite, and water. Special chemicals are added to the drilling fluid to compensate for the varying composition of the water and the formation being drilled and to increase the weight of the column. The drilling fluid can contain a gel for its slip properties and/or any kind of conventional filler. The drilling fluid is used in oil, gas and water drilling to carry rock cuttings to the surface and to lubricate and cool the drilling bit. The drilling fluid, by hydrostatic pressure, helps prevent the collapse of unstable strata into the hole and the intrusion of water from water-bearing strata that may be encountered. The drilling fluid is used to increase or decrease pressure in the drill hole, to cool and lubricate the drill bit and other machinery and to coat delicate formation whose exposed surfaces in the drill hole (well bore) need protection.
The modern technique of drilling oil and gas wells is to drill using a rotary drill, i.e., turning steel knuckles or teeth (of tungsten), located on the drill pipe. Drilling fluid is a fluid that helps cool the drilling bit (or teeth) while transporting rock cuttings to the surface. The drilling fluid also serves to keep any oil or gas underground--the hydrocarbons in the rock strata are usually under pressure and tend to blow or spew out of the well hole.
With rotary drilling, the drill bit rotates while bearing down on the bottom of the well, thus gouging and chipping its way downward. When conducting rotary drilling, the well bore is kept full of liquid during drilling. A weighted fluid (called drilling fluid or mud) in the bore hole serves at least two important purposes: (a) by its hydrostatic pressure, it prevents the entry of formation fluids into the well thus preventing blowouts and gushers; and (b) the drilling fluid carries the crushed rock to the surface, so that the drilling is continuous until the bit wears out. The drill bit is connected to the surface equipment through a drill pipe, a heavy-walled tubing through which the drilling mud is fed to the bottom of the bore hole. In most cases, the drill pipe also transmits the rotary motion from a turntable at the surface to the drilling bit at the bottom of the hole. The top piece of the drill pipe is a tube of square or octagonal cross section called the kelly, which passes through a square or octagonal hole in the turntable (located near the bottom of the derrick). The drilling fluid leaves the drill pipe in such a way that it washes the loose rock from the bottom and carries it to the surface. The drilling bit has a number of jets through which the drilling fluid is forced by pressure into the bottom of the drill hole. Drilling fluid is carefully formulated to the correct weight and viscosity characteristics for its required tasks. After screening to remove the rock chips, the returning drilling fluid is usually held in open pits for recirculating through the well. The drilling fluid is picked up by piston pumps and forced through a swivel joint into the top of the drill pipe. When a worn drilling bit is being changed, the drilling fluid is left in the bore hold to prevent excessive flow of fluids into the well from the surrounding rock and sand.
Bentonite at a concentration of about 28.8 lbs/bbl of water (8.2 percent) provides a slurry with good rheological characteristics (i.e., high viscosities with yield stress behavior at low shear rates denoting solids carrying capacity away from the drill bit, and relatively low viscosities at high shear rates in the vicinity of the drill bit to minimize torque requirements). Bentonite in fresh water also forms an excellent filter cake on the wall of the wellbore and thus ensures low fluid loss in a formation of variable permeability. Bentonite drilling fluids of about 28 lbs/bbl concentrations are relatively high in total solids and density. These factors lead to a reduction in the rate at which a wellbore can be drilled to a given depth. Two other major disadvantages associated with high total solids bentonite drilling muds are the high cost of transportation and storage, which can be substantial for drilling sites located in distant and hostile environments, and in drilling formations with high shale contents. The shale is hydrated by the aqueous medium which results in fines, increasing the viscosity of the drilling fluid, and in sloughing from sites previously drilled. Shale hydration inhibitors such as calcium chloride cannot be used as they interact with bentonite particles, resulting in many detrimental changes (e.g., phase separation) to the mud.
In the formulating of drilling fluids, a clay such as bentonite is usually added to water to prepare an aqueous mud. In other cases drilled shales are allowed to accumulate in the mud as drilling progresses in order to build up properties such as weight, viscosity and gel strength. Sometimes muds with oil as the continuous phase are used to prevent hole problems, and in other cases flocculants are added to aqueous mud to aid in dropping cut solids at the surface. The result of using such a clay-based mud system has been a build-up of undesirable solids, either in the circulating mud or in the form of excess mud which is stored in reserve or disposal pits. This build-up, if not properly dealt with, will cause increases in unit weight (specific gravity), viscosity and gel strength to such high levels that a number of undesirable events may occur. The mud cake on the wellbore wall may become so thick that swabbing occurs in pulling the bit, causing sloughing or caving of the wall and further increases in viscosity and gel strength. Drilling rate may decrease because of the thick filter cake on bottom. The fluid may even become so thick as to be unpumpable. To try to avoid such problems, a close watch is kept on the circulating mud and rather expensive preventive steps taken. Flocculants are added in the settling pits in attempts to bring about agglomeration and settling of the hydrated and dispersed drilled solids, a step likely to remove some of the originally added bentonite as well. A fraction of the mud is discarded or laid aside, and the balance is thinned to the desired unit weight with water. In so thinning, the concentrations of some if not all constituents of the mud are reduced below the desired levels. In such case the only recourse available is to add more of the very materials just thrown out in the discarded fraction, primarily bentonite but also many of the other additives used for fluid lose control and various other properties.
The usual clay bentonite-type drilling mud systems have limitations that require the use of various drilling additivies to control flow properties when the fluid encounters conditions in drilling operations which might detrimentally alter mud properties. These changes result in lower drilling and penetration rates and delays in drilling operations, which, in turn, increase overall drilling costs. In many cases with conventional drilling fluids, such additives only create more problems. This is due to the fact that while serving to control a specific mud property the additive may produce additional undesirable effects on the mud system. Such may result from the additive being incompatible with other components in the system, or may be due to a direct effect on mud properties. Also, such drilling fluids are adversely affected when they become contaminated with calcium compounds, potassium or sodium chlorides, etc. Thus, with high salt or calcium contamination, the effect on yield point, gel strengths and fluid loss characteristics of such conventional muds renders the latter essentially useless unless special treatment procedures are employed. In the case of high salt contamination, bentonite muds are usually not run. Instead, salt gel or attapulgite is used as a viscosifier. Even in the case of a prehydrated bentonite which is suddenly contaminated with salt, serious detrimental effects on flow properties result. This is particularly true in the case of highly dispersed muds. For example, the plastic viscosity decreases, the fluid loss increases, and the gel strengths increase.
Water provides the fastest drilling rate of any liquid; however, such a fluid does not have the viscosity profile suitable for carrying drill solids to the surface from any significant depth. In addition, aqueous solutions readily hydrate the different types of shale in certain formations which can result in swelling and sloughing of the clay, leading to cave-in of the walls in previously drilled sections or balling near the drill bit. Use of various salt solutions can be employed in part to inhibit hydration of such shales. It is common in the art to employ water-soluble polymers (W-SPs) to thicken such solutions, in part, to retard migration of the salts into the formation and in part to synergistically improve stabilization of the shale. The water-soluble polymers also provide the viscosity necessary for lifting drilled solids from the wellbore. Such thickened fluids are known to provide extremely fast drilling rates. Shear stresses in the immediate vicinity of the drill bit are high (.about.10.sup.5 sec.sup.-1). Under such shear stresses most water-soluble polymers are degraded, with a subsequent lowering of the solution viscosities.
Polymer beneficiation of bentonite can provide a compromise between the advantages and disadvantages associated with the two types of drilling fluids described above. Polymer beneficiation permits the use, generally, of one-half of the normal amount of bentonite required to reach a given viscosity and the lower density of such a fluid, in part, allows faster drilling rates. In addition bentonite of poorer quality can be used, after being beneficiated, to achieve a given viscosity. In beneficiating a clay the viscosifying power of the polymer becomes less shear sensitive (i.e., the drop in viscosity will be less per pass through the drill bit area).
U.S. Pat. No. 3,070,543 teaches that a vinyl acetate/maleic acid copolymer is effective in beneficiating bentonite and flocculating drill solids in fresh water slurries. U.S. Pat. Nos. 3,360,461, 3,472,325 and 3,558,545 disclose that the use of acrylamide/acrylic acid copolymers of intermediate hydrolysis or of low hydrolysis, blended with polyacrylic acid are more effective in beneficiating low solids bentonite muds than the maleic acid/vinyl acetate copolymer (MAVAC). In such disclosures the use of polyacid beneficiating agents are restricted in certain concentration ranges. Below a certain critical concentration the polymers are not effective and above a certain concentration the water-soluble polymers act as flocculants instead of beneficiating agents. These factors limit the ability of such beneficiating agents to increase the low shear viscosity of low-solid bentonite slurries which is needed for lifting drill solids from the formation. The employment of small amounts of the calcium salt of acrylic acid has been disclosed in U.S. Pat. No. 4,087,365 to resolve this deficiency in relatively fresh water slurries. Although a need for beneficiating agents that are effective in saline solutions is noted in U.S. Pat. No. 3,360,461, all of the patents cited above describe materials that are ineffective in dealing with the salinities (particularly the presence of divalent ions) encountered in many connate waters of subterranean formations. This is not surprising since the beneficiating agents described in the patents are synthetic polyacids, which are susceptible to adverse interactions with divalent ions.
The art has envisaged that bentonite slurries compatible with saline environments might be obtained if the beneficiating agents were nonionic, such as poly(ethylene oxide). Intermediate to high molecular weight poly(ethylene oxide) has been disclosed (U.S. Pat. No. 3,525,688) to be an effective fluid loss control agent for bentonite muds at high levels (i.e., 6 lbs/bbl), but also to adversely affect the rheological characteristics of such muds. Intermediate molecular weight polyethylene glycols have been employed to lower the viscosity (U.S. Pat. No. 2,589,949) of resurfaced bentonite muds. The use of high molecular weight poly(ethylene oxides) in combination with various types of polyacids have also been disclosed (U.S. Pat. No. 3,687,846) to enhance the properties of fresh-water bentonite slurries.
U.S. Pat. No. 3,953,336 teaches that Xanthomonas campestris polysaccharide (XCPS) proficiently disperses bentonite and other drilled solids. However, the XCPS is extremely susceptible to enzyme attack. The patent observes that the use of Xanthomonas compestris polysaccharide/hydroxyethyl cellullose in clay-free drilling fluids is observed to stabilize shale particularly in the presence of potassium chloride. The use of Xanthomonas compestris polysaccharide only with magnesium oxide is disclosed by U.S. Pat. No. 3,988,246 to be an effective drilling thickener; however, lignosulfonates have to be added to such formulations "to maintain good properties of the drilling mud" because solids removal is difficult without hydroxyethyl cellulose (see U.S. Pat. Nos. 3,844,361 and 3,852,201). The favorable aspects of hydroxyethyl cellulose in the stabilization of typical shale formations also is disclosed by Weiss (German Pat. No. 2,524,991).